Hydrogen sulfide removal process

ABSTRACT

A process is presented to treat a process stream containing a hydrocarbon (oil and/or gas) and hydrogen sulfide with a liquid treatment solution containing a sulfur dye catalyst. The process stream can be within a pipeline, wellbore, subsea pipeline or a wellhead that contains hydrogen sulfide where the liquid treatment solution is injected at a predetermined point to define a scavenger zone such that the sulfur dye catalyst in the liquid treatment solution causes the sulfide from the hydrogen sulfide to react with the catalyst. The hydrocarbon component is separated substantially free of the hydrogen sulfide from a spent treatment solution containing spent sulfur dye catalyst which can then be fed to an oxidation vessel where it is contacted with an oxygen containing gas causing the sulfide to oxidize to thiosulfate and converting the spent sulfur dye catalyst to regenerated sulfur dye catalyst. The thiosulfate can be recovered, and the regenerated sulfur dye catalyst can be recycled as part of the liquid treatment solution.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application is a continuation of U.S. patent applicationSer. No. 16/160,549 filed Oct. 15, 2018 which is herewith incorporatedby reference into the present application.

TECHNICAL FIELD

The present disclosure is directed to a method and apparatus forcontinuously removing hydrogen sulfide gas (H₂S) from a process streamflowing in a pipe, such as a hydrocarbon/water mix in subsea pipeline, awellbore or in a well head. The method involves absorption of the H₂S inan aqueous treatment solution that contains a sulfur dye catalyst, wherethe sulfide in the H₂S reacts with the catalyst. The spent aqueoustreatment solution can be followed by an oxidation reaction to producethiosulfate. The spent sulfur dye catalyst can also be regenerated inthe oxidizer using an oxygen-containing gas and then recycled for use aspart of the aqueous treatment solution.

BACKGROUND

The removal of sulfur contaminants, specifically H₂S, from oilcontaining process streams using aqueous salt streams is known.Likewise, the removal of H₂S from hydrocarbon containing gas streams isknown. However, these known processes typically use expensive scavengingchemicals and do not directly produce useful chemicals. Accordingly,there is a need to develop economical processes for treatinghydrocarbons in pipelines that can selectively remove H₂S from theseprocess streams at ambient temperatures and with the potential toconvert the removed sulfide to produce a useful liquid product. Theseand other advantages will become evident from the following moredetailed description of the present disclosure.

SUMMARY

This disclosure relates to a process for treating a hydrocarbon processstream contained in a pipeline that is contaminated with hydrogensulfide (H₂S) to obtain a treated hydrocarbon substantially free of H₂Sand optionally a separate liquid aqueous stream containing thiosulfates.The hydrocarbon process stream can include both liquid and gaseoushydrocarbons, and in some cases water. Specifically, one possibleembodiment of this disclosure includes a process to treat H₂S present ina subsea pipeline, where a liquid treatment solution comprising a sulfurdye catalyst is injected into a subsea pipeline that can contain oil,water, and hydrogen sulfide. The injected treatment solution causes anadmixture to form, where the point of injection of the liquid treatmentsolution into the subsea pipeline is selected at a measurable distancebelow sea level such that a scavenger region is defined within thepipeline where the hydrogen sulfide is absorbed into the liquidtreatment solution and reacts with sulfur dye catalyst to form a spentsulfur dye catalyst. Absorption of the hydrogen sulfide in the liquidtreatment solution forms sulfides that can bind to the sulfur dyecatalyst and/or to other sulfides. The admixture is then sent to aseparator where treated hydrocarbon and dissolved gas is separated froma spent treatment solution comprising the spent sulfur dye catalyst andwater.

The above described embodiment can also include directing the spenttreatment solution into an oxidation vessel, where an oxygen containinggas is added to the oxidation vessel to regenerate the spent catalystand produce thiosulfate from dissolved sulfide species. Excess oxygencontaining gas from the oxidation vessel is removed as well as a liquidstream of regenerated liquid treatment solution comprising thethiosulfate and the regenerated sulfur dye catalyst. In somecircumstance it may be desirable to recycle the regenerated liquidtreatment solution to the point of injection into the subsea pipeline.Preferably, a predetermined thiosulfate concentration in the regeneratedliquid treatment solution is maintained by removing a portion of theregenerated liquid treatment solution from the process.

To compensate for a loss or depletion of the total amount of catalyst inthe process, a make-up catalyst stream can be mixed with regeneratedliquid treatment solution to form part of the liquid treatment solutioninjected into the subsea pipeline. The make-up catalyst streampreferably comes from a storage tank and comprises fresh liquidtreatment solution containing fresh sulfur dye catalyst.

A portion of the regenerated liquid treatment solution can be introducedinto a second separation process where the regenerated sulfur dyecatalyst is separated from the thiosulfate by a filtration step and canthen be recirculated as part of the liquid treatment solution injectedinto the subsea pipeline. The filtration step preferably uses a filtermedia that collects the regenerated sulfur dye catalyst. A back-flushingstep can also be used to remove the regenerated sulfur dye catalyst fromthe filter media. A preferred back-flushing procedure comprisescontacting the filter media with a liquid solution that can solubilizethe regenerated sulfur dye catalyst such that it can be removed from thefilter media. In some cases, a liquid solution containing sulfide can beused.

In another embodiment, a process is disclosed to treat hydrogen sulfidepresent in a downhole well that includes injecting a liquid treatmentsolution comprising a sulfur dye catalyst into a downhole well that cancontain oil, water, and hydrogen sulfide to form an admixture, where thepoint of injection of the liquid treatment solution into the downholewell is selected at a measurable distance below ground level to define ascavenger region within the downhole well such that the hydrogen sulfideis absorbed into the liquid treatment solution and reacts with sulfurdye catalyst to form a spent sulfur dye catalyst. The admixture leavingthe scavenger region is then sent to a first separator where the oil anddissolved gas is separated from a spent treatment solution comprisingthe spent sulfur dye catalyst and water. The spent treatment solutioncan then be directed to and introduced into an oxidation vessel.

An oxygen containing gas is introduced into the oxidation vessel toregenerate the spent sulfur dye catalyst and produce thiosulfate fromdissolved sulfide species. Excess oxygen containing gas is removed fromthe oxidation vessel. Separately removed is a liquid stream ofregenerated liquid treatment solution comprising the thiosulfate and theregenerated sulfur dye catalyst. All or a portion of the regeneratedliquid treatment solution can be sent to a second separation processwhere the regenerated sulfur dye catalyst is separated from thethiosulfate by a filtration step and is recirculated to form all or partof the liquid treatment solution injected into the downhole well. Asdescribed above, the filtration step can use a filter media thatcollects the regenerated sulfur dye catalyst and include a back-flushingprocedure to recover the regenerated sulfur dye catalyst

The second embodiment just described can also include directing thedissolved gas separated from the oil and spent liquid treatment solutionin the first separator into a bottom portion of an absorber where thedissolved gas comprising hydrogen sulfide flows upward contacting astream of liquid treatment solution flowing downward from a top portionof the absorber. Residence time of the liquid treatment solution anddissolved gas within the absorber is preferably controlled such that thehydrogen sulfide is absorbed into the liquid treatment solution andreacts with the sulfur dye catalyst forming a spent sulfur dye catalyst.The spent treatment solution removed from the absorber vessel containsthe spent sulfur catalyst and water. The spent treatment solution fromthe absorber can be introduced into a second oxidation vessel, where anoxygen containing gas is also added into the second oxidation vessel toregenerate the spent sulfur dye catalyst and produce thiosulfate fromdissolved sulfide species.

Excess oxygen containing gas can then be removed from the secondoxidation vessel separately from the removal of a liquid stream ofregenerated liquid treatment solution comprising the thiosulfate and theregenerated sulfur dye catalyst. The regenerated liquid treatmentsolution can be divided into a first and a second portion, where thesecond portion is recycled to the absorber and the first portion isintroduced into a second separation process where the regenerated sulfurdye catalyst is separated from the thiosulfate by a second filtrationstep and is recirculated to the absorber vessel. As indicated above, thesecond filtration step can employ a filter media that collects theregenerated sulfur dye catalyst and produces a thiosulfate solution thatcan be removed from the process for further processing to produce athiosulfate product stream.

In yet another embodiment the liquid treatment solution of the presentdisclosure can be injected into a wellhead to treat an oil stream thatcan contain oil, water, and contaminated with hydrogen sulfide to forman admixture, where the point of injection of the liquid treatmentsolution into the wellhead pipeline is at a predetermined distance aboveground level. This predetermined distance is defined as a scavengerregion where the maximum amount of sulfide is absorbed into the injectedliquid treatment solution. There are a number of accepted methods formixing liquids and/or dispersing one or more fluids into another phase,each involving the use of a mechanical apparatus, such as, quills,spargers, and static mixers, each of which can increase mass transferbetween a scavenger compound and the hydrocarbon to be treated.

In the present disclosure, determining the optimum point of injection ofthe liquid treatment solution and thus defining the previously mentionedscavenger region, employs a method that relies on and allows theturbulence of a fluid following in a pipeline or conduit to create shearfor mixing an injected fluid into the fluid flowing in the pipe. Acombination of Reynolds and Schmidt numbers can provide a basis formodeling for mixing an injected fluid into a pipe containing a flowingfluid. From such a model an optimum point of injection can be determinedalong a given length of pipe. As the fluid velocity increases in a givenpipe, the length of pipe required for mixing is lowered. Flow in ahorizontal pipe, for instance, will switch from horizontal bubble flowto dispersed flow, increasing mass transfer and requiring less distancefor treating. This determination can further be modeled in computationalflow dynamics (CFD) to determine the appropriate length or distance ofpipe that is required to mix the two phases. In the present disclosure,sampling at the end of the predetermined distance can confirm thatmaximum absorption of the sulfide into the liquid treatment solution isachieved. In some cases, the sampling could indicate that the point ofinjection may need to be moved to increase the predetermined distanceand thus increasing the length of the scavenger zone. The goal is tocreate a scavenger zone where a maximum of the hydrogen sulfide isremoved as sulfide through being absorbed into the liquid treatmentsolution to create a spent sulfur dye catalyst.

The admixture from the wellhead is introduced into a separator where theoil and dissolved gas is separated from a spent treatment solutioncomprising the spent sulfur dye catalyst and water. The spent treatmentsolution is then fed into an oxidation vessel to regenerate the spentsulfur dye catalyst and produce thiosulfate from dissolved sulfidespecies. Excess oxygen containing gas is removed from the oxidationvessel along with a separately removed stream of regenerated liquidtreatment solution comprising the thiosulfate and the regenerated sulfurdye catalyst, which is fed to a second separation process where theregenerated sulfur dye catalyst is separated from the thiosulfate by afiltration step. Part or all of the regenerated sulfur dye catalyst isrecirculated to form all or part of the liquid treatment solutioninjected into the wellhead well. This filtration step can use a filtermedia that collects the regenerated sulfur dye catalyst. A black-flushprocedure can be used to recover the catalyst and reinject with make-upcatalyst solution.

The dissolved gas separated from the admixture is fed into a bottomportion of an absorber where the dissolved gas comprising hydrogensulfide flows upward contacting a stream of liquid treatment solutionflowing downward from a top portion of the absorber. The residence timeof the liquid treatment solution and dissolved gas within the absorberis monitored and controlled such that hydrogen sulfide in the dissolvedgas is absorbed into the liquid treatment solution and reacts with thesulfur dye catalyst forming a spent sulfur dye catalyst. A spenttreatment solution is removed from the absorber vessel comprising thespent sulfur dye catalyst and water and introduced into a secondoxidation vessel, where it contacts an oxygen containing gas toregenerate the spent sulfur dye catalyst and produce thiosulfate fromdissolved sulfide species.

Excess oxygen containing gas from the second oxidation vessel isremoved. A separate stream of regenerated liquid treatment solutioncomprising the thiosulfate and the regenerated sulfur dye catalyst isalso removed from the second oxidation vessel. This stream ofregenerated liquid treatment solution is divided into a first and asecond portion, where the second portion is recycled to the absorber.The first portion is fed to a second filtration process where theregenerated sulfur dye catalyst is separated from the thiosulfate and isrecirculated to the absorber vessel. The thiosulfate recovered duringthe process can be transported further for various applications.

In another embodiment, the liquid treatment solution of the presentinvention is injected into a pipeline that can contain hydrogen sulfide,oil and water to form an admixture. The point of injection into thepipeline is at a predetermined distance from a separator to define ascavenger region where the hydrogen sulfide is absorbed into the liquidtreatment solution, where it reacts with the sulfur dye catalyst forminga spent sulfur dye catalyst. The admixture is then fed into theseparator where the oil containing residual dissolved hydrogen sulfideis separated from the dissolved gas and from a spent treatment solutioncomprising the spent sulfur dye catalyst and water. The separated oiland residual dissolved hydrogen sulfide is mixed with a second amount ofliquid treatment solution such that the residual dissolved hydrogensulfide is absorbed into the second amount of liquid treatment solutionand reacts with the sulfur dye catalyst forming a spent sulfur dyecatalyst. This mixture is fed to an inline mixer and the mixture exitingthe inline mixer is fed to a phase separator where treated oil isseparated from spent liquid treatment solution and is removed from theprocess.

The spent treatment solution containing spent sulfur dye catalyst isremoved from the phase separator vessel and introduced into an oxidationvessel, where it is contacted with an oxygen containing gas toregenerate the spent catalyst and produce thiosulfate from dissolvedsulfide species. Excess oxygen containing gas is removed from theoxidation vessel along with a separately removed liquid stream ofregenerated liquid treatment solution comprising the thiosulfate and theregenerated sulfur dye catalyst.

The just described process can also include dividing the regeneratedliquid treatment solution from the oxidation vessel into a first and asecond portion, where the second portion is recycled to form part of theliquid treatment solution injected into the pipeline. The first portioncan be fed into filtration process where the regenerated sulfur dyecatalyst is separated from the thiosulfate and then recirculated to bepart of the liquid treatment solution injected into the pipeline.Additionally, the dissolved gas removed in the separation process andthe spent liquid treatment solution can each independently be furthertreated as described above to recover a regenerated sulfur dye catalystand a thiosulfate product.

The treatment solution contains a catalyst as described in detail belowand can contain anions of alkali or ammonia salts and cations ofhydroxide, sulfide or carbonate, such as, potassium carbonate, potassiumhydroxide, calcium carbonate, sodium hydroxide, sodium carbonate,ammonia, and potash. Additionally, solutions of ammonia or alkali metalsalts of weak acids such as carbonic, boric, phosphoric and carbolicacids, or aqueous solutions or organic bases such as ethanol-amines canbe used, as well as, aqueous solutions of alkali metal salts ofamino-carboxylic acids such as glycine or alanine.

The salt concentration in the treatment solution is preferably between 0wt. % and a quantity sufficient to saturate the solution. Where anabsorber is used in the process it is preferred that the feed stream andtreatment solution preferably contact each other in a countercurrentflow scheme, however, a co-current flow could also be utilized. Theabsorber may contain physical components to assist in the contacting ofthe feed and treatment solution, such as, baffling, packing, trays,static mixers, valves, fiber film type materials, or other materialsthat increase the contact area between the feed stream and the treatmentsolution. The amount of treatment solution used is based on theconcentration of H₂S in the pipeline, well bore, well head or subseapipeline, as well as the feed rate. The concentration can be determinedthrough sampling and subsequent lab analysis. Sulfide ions are formedupon H₂S absorption in the treatment solution which are then adsorbed onthe catalyst for the further reaction. Later, the sulfide ions can beoxidized in a separate oxidation step in an oxidizer vessel to formthiosulfate. The produced thiosulfate remains in the treatment solution.When potassium salts are present in the treatment solution, potassiumthiosulfate is selectively formed. A substantially H₂S-free productstream is removed from the absorber for further processing ortransportation.

The catalyst used to oxidize the sulfide ions to thiosulfate in theoxidizer is preferably in the form of vat dyes or metal sulfates andmore preferably in the form of sulfur dyes and/or sulfurized vat dyes.Sulfurized vat dyes are chemically and structurally similar to sulfurdyes including having the disulfide/thiolate functionality. They aregiven the vat dye designation because they are typically obtained usinga vat dye process. Sulfur dyes and sulfurized vat dyes which may beutilized in accordance with the method of the invention include but arenot limited to the following (“C.I.” stands for “Color Index”):

C.I. Sulfur Yellow 1, 2, 3, 4, 5, 6, 8, 9, 10, 11, 12, 13, 14, 16, 20and 23, C.I. Leuco Sulfur Yellow 2, 4, 7, 9, 12, 15, 17, 18, 21, 22 and23 and C.I. Solubilized Sulfur Yellow 2, 4, 5, 19, 20 and 23;

C.I. Sulfur Orange 1, 2, 3, 4, 5, 6, 7 and 8, C.I. Leuco Sulfur Orange1, 3, 5 and 9 and C.I. Solubilized Sulfur Orange 1, 3, 5, 6, 7 and 8;

C.I. Sulfur Red 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 12 and 13, C.I. LeucoSulfur Red 1, 4, 5, 6, 11 and 14 and C.I. Solubilized Sulfur Red 3, 6,7, 11 and 13;

C.I. Sulfur Violet 1, 2, 3, 4 and 5, C.I. Leuco Sulfur Violet 1 and 3and C.I. Solubilized Sulfur Violet 1;

C.I. Sulfur Blue 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16,17, 18 and 19, C.I. Leuco Sulfur Blue 1, 2, 3, 5, 7, 8, 9, 11, 13, 15and 20 and C.I. Solubilized Sulfur Blue 1, 2, 4, 5, 6, 7, 10, 11, 13,and 15;

C.I. Sulfur Green 1, 2, 3, 4, 5, 6, 7, 8:1, 9, 10, 11, 12, 13, 14, 15,16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 31, 32 and 33,C.I. Leuco Sulfur Green 1, 2, 3, 4, 7, 11, 16 30, 34, 35, 36, and 37 andC.I. Solubilized Sulfur Green 1, 2, 3, 6, 7, 9, 19, 26, and 27;

C.I. Sulfur Brown 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 14:1,15, 15:1, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30,31, 32, 33, 34, 35, 36, 37, 38, 39, 40, 41, 42, 43, 44, 45, 46, 47, 48,49, 50, 51, 52, 53, 53:1, 54, 55, 56, 57, 58, 59, 60, 61, 62, 63, 64,65, 66, 67, 68, 69, 70, 71, 72, 73, 74, 76, 77, 78, 79, 84, 85, 87, 88,89, 90, 91, 93, and 94;

C.I. Leuco Sulfur Brown 1, 3, 4, 5, 8, 10, 11, 12, 14, 15, 21, 23, 26,31, 37, 43, 44, 81, 82, 86, 87, 90, 91, 92, 93, 94, 95 and 96 and C.I.Solubilized Sulfur Brown 1, 4, 5, 8, 10, 11, 12, 14, 15, 16, 21, 26, 28,31, 51, 52, 56, 60, 75, 80, and 83;

C.I. Sulfur Black 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16and 17;

C.I. Leuco Sulfur Black 1, 2, 6, 9, 10, 11, and 18;

C.I. Solubilized Sulfur Black 1, 2, 5, 7, and 11; and,

C.I. Vat Yellow 21, C.I. Vat Orange 21, C. I Vat Green 7, C.I. Vat Blue7, 42, 43, Vat Black 11.

A more complete listing of the sulfur dyes and sulfurized vat dyesmentioned herein above may be found in the Color Index, 3^(rd). Ed.,issued by the Society of Dyers and Colorists (London, GB), as well as inthe supplementary volumes published there to and in the Color IndexInternational, 4^(th) Edition Online which are hereby incorporated byreference.

Other, though less preferable catalysts for the conversion of sulfide tothiosulfate which may be used include: sulfate lignin, copper salts ofsulfate and chloride, iron salts of hydroxide, chloride, sulfide, orsulfate, phthalocyanines of copper and cobalt, manganese salts ofsulfate or chloride, polyvalent phenols such as pyrocatechol orpyrogallol, and quinones such as tetra-t-butyl stilbene quinone.

The reaction of the sulfide ions from the H₂S with the catalyst in thepipeline, wellbore, well head, or the absorber causes the catalyst toundergo a reduction process. The composition of a subsea pipeline can beany combination of gas (C1-C4), hydrocarbon oil (C5-C19), brine (0-30 wt%) and >0 ppm H2S. A typical gas to oil ratio 0-100 v/v and gas to waterratio 0-100 v/v. Likewise, a wellbore or a wellhead can comprise anycombination of gas (C1-C4), hydrocarbon oil (C5-C19), brine (0-30 wt %)and >0 ppm H2S. A typical gas to oil ratio 0-100 v/v and gas to waterratio 0-100 v/v. In order to maximize the economic benefit of theprocess, it is desirable to reuse the catalyst. This can be achieved byregenerating the spent catalyst to its active form, i.e., the catalystmust be oxidized. This is accomplished in an oxidation step in thepresence of an oxygen-containing gas as described more fully below.

The spent treatment solution containing the spent catalyst is introducedinto an oxidizer vessel where the spent catalyst is oxidized to itscatalytically active form and the sulfide is converted to thiosulfate.An oxygen containing gas, for example, air, is preferably introducedinto the oxidizer in the form of a sparged gas stream, however, theoxygen containing gas can also be introduced by any type of gas/liquidcontact device such as across mixers, valves, packing, or membranes. Theoxygen reacts with sulfides bound to the catalyst to form thiosulfateand a regenerated catalyst in its oxidized state.

The scavenger region in a subsea pipeline is adjusted by varying theinjection point of the liquid treatment solution. Preferably, thescavenger region is selected in the range of 500 to 3000 m from sealevel to provide a residence time 5 minutes or more. A residence time inthe oxidizer vessel of at least 5 minutes is usually sufficient to fullyoxidize the spent catalyst. Excess oxygen-containing gas that is notconsumed in the oxidation reaction is removed as an off-gas stream fromthe top of the oxidizer. Once the oxidation step is complete, theregenerated treatment solution containing the thiosulfates is removedfrom the oxidizer and can be recycled back to the point of injection inthe pipeline, wellhead, wellbore or the absorber for contacting with anyoil and water stream containing H₂S, thus completing a continuousprocessing operation. Fresh treatment solution can be added to thisrecycled regenerated treatment solution as make-up stream. Optionally, aportion of the regenerated treatment solution can be removed to preventa buildup of thiosulfate in the treatment solution. This removed portionof the regenerated treatment solution is then further processed asdescribed in more detail below to remove the regenerated catalyst forrecycle and to produce a thiosulfate product stream that is a usefulproduct in a variety of industrial and agricultural manufacturingprocesses, for example the production of fertilizer.

The operating parameters of the above-described absorber/oxidationprocesses include temperatures in the range of from about 15° C. toabout 100° C., preferably in the range from about 40-70° C. The pressureof the vessels can range from atmosphere to 150 barg, preferably fromabout 0.5-30 barg. Reaction times can range from about 5-240 mins,preferably less than 30 min. The process can be run as a batch orcontinuous operation.

The present disclosure also provides a treatment process where “producedwater” can be processed to supply useful on-site chemicals useful in thescrubbing and removal of H₂S from fluid feed streams. Produced water isa term used in the oil industry to describe water that is produced orcollected as a byproduct along with oil and gas recovered from wells.Oil and gas reservoirs often have significant quantities of water, aswell as hydrocarbons, sometimes in a zone that lies under thehydrocarbons, and sometimes in the same zone with the oil and gas. Oilwells sometimes produce large volumes of water with the oil, while gaswells tend to produce water in smaller proportion. To achieve maximumoil recovery, it is sometimes necessary to employ waterflooding, inwhich water is injected into the reservoirs to help force the oil to theproduction wells. The injected water eventually reaches the productionwells, and so in the later stages of waterflooding, the produced waterproportion of the total production increases. The water compositionranges widely from well to well and even over the life of the same well.Much of the produced water is recovered having varied high concentrationof salts (i.e., hardness) and having high amounts of total dissolvedsolids, thus rendering the produced water unacceptable for beneficialreuse. All produced water also contains oil and suspended solids. Someproduced water contains metals such as zinc, lead, manganese, iron andbarium.

Historically, produced water was disposed of in large evaporation ponds.However, this has become an increasingly unacceptable disposal methodfrom both environmental and social perspectives. As such, produced wateris commonly considered an industrial waste.

The water hardness in the form of dissolved ions, especially alkalicarbonates, contained in produced water can be reused by the presentlydisclosed process to capture the hydrogen sulfide contaminate in thenatural gas and oil thereby reducing the demand for oilfield chemicals.In one embodiment of the presently disclosed process, produced water canbe first subjected to a traditional 3-phase separator, where gas,hydrocarbon and aqueous phases are separated from each other.Alternatively, the produced water could be mixed with a portion ofregenerated liquid treatment solution and then separated in a 3-phaseseparator. The aqueous phase is then directed to the above-describedoxidizer vessel where it contacts the sparged oxygen-containing gas,spent treatment solution and newly oxidized (regenerated) treatmentsolution. Since the aqueous phase usually contains some amount ofsulfides, typically in the range from about 2 ppm to about 1,200 ppm, asa result dissolved H₂S, the oxygen in the sparged gas combined with thenewly regenerated catalyst causes oxidation of these aqueous phasesulfides and converts them to thiosulfate. These produced thiosulfatesfrom the aqueous phase remain in the treatment solution as the treatmentsolution continues to undergo regeneration in the oxidizer.

The removed regenerated treatment solution that now contains the treatedaqueous phase recovered from the produced water has an OxidationReduction Potential (ORP) greater than that of the ORP of both theoriginal separated aqueous phase and the spent treatment solution.

ORP, also referred to as reduction potention, oxidation/reductionpotential or redox potential is a measure of the tendency of a chemicalspecies to acquire electrons and, as such, be reduced. Typically, ORP ismeasured in volts (V), or millivolts (mV). Each species has its ownintrinsic reduction potential; the more positive the potential, thegreater the species' affinity for electrons and tendency to be reduced.ORP is a commonly used as a measurement for water quality. In aqueoussolutions, reduction potential is a measure of the tendency of thesolution to either gain or lose electrons when it is subject to changeby introduction of a new species. A solution with a higher (morepositive) reduction potential than the new species will have a tendencyto gain electrons from the new species (i.e. to be reduced by oxidizingthe new species) and a solution with a lower (more negative) reductionpotential will have a tendency to lose electrons to the new species(i.e. to be oxidized by reducing the new species). Because the absolutepotentials are difficult to accurately measure, reduction potentials aredefined relative to a reference electrode. Reduction potentials ofaqueous solutions are determined by measuring the potential differencebetween an inert sensing electrode in contact with the solution and astable reference electrode connected to the solution by a salt bridge.In the present disclosure, a measurement of the ORP of the solution inthe absorber and/or in the oxidizer can be used to control the flow oramount of oxygen containing gas that is introduced into the oxidizer.

The treated aqueous phase and regenerated treatment solution referred toas a recycle treatment stream is then sent to the absorber where it iscontacted with the feed stream containing oil, gas, or both. Therecycled treatment stream is contacted with the oil/gas to the extractthe hydrogen sulfide contaminants from the oil/gas forming sulfides thatare then oxidized to form thiosulfates. The resultant treatment solutionthat now contains spent catalyst is sent to the oxidizer vessel wherethe spent catalyst is oxidized to its active form and making itavailable for the oxidation of any residual sulfides, including sulfidesentering the oxidizer vessel in the aqueous stream separated from theproduced water.

The regenerated treatment solution containing the treated aqueous phasecan now be removed from the oxidizer vessel when the ORP of theregenerated solution is greater than −0.4 mV. This removed regeneratedtreatment solution can then be filtered to remove the regeneratedcatalyst, yielding a stream of water with thiosulfate ions ranging inconcentration from about 0 wt. % to about saturation. The saturationconcentration depends on type of cation, e.g. approx. 51 wt. % forpotassium. The filter media that recovers and holds the removed catalystcan be periodically backflushed with a flush solution, preferably aflush solution containing dissolved sulfides. Performing the backflushing operation on the filter media allows the regenerated catalystto be removed and reused in the process, thus minimizing catalyst lossand reducing the amount of fresh (make-up) treatment solution. By usinga flushing solution containing sulfides the solubility of the filteredregenerated catalyst is enhanced and improves the efficiency of cleaningthe filter.

Regarding the aqueous phase that can be fed to the oxidizer, it may benecessary, depending on the source of the produced water, to increasethe measured hardness by adding to the produced water and/or separatedaqueous phase lime, potash, other sources of alkali hydroxide orcarbonate, and mixtures thereof. Once the catalyst is filtered, it isnow possible to send all or a portion of this filtered regeneratedtreatment solution to disposal via well injection in a manner similar tocurrent practice of injecting recovered produced water. In the abovedescribed embodiment, the treatment of the gas or oil and thensubsequent disposal of the aqueous phase directly on-site or close tothe oil/gas wells provides a method that greatly reduces the costs ofprocuring chemicals and instead uses chemicals that are readilyavailable in the produced water.

Likewise, using the produced water obtained on-site allows the treatmentsolution to be prepared on-site from concentrates and avoids the need totransport large quantities water normally used to prepare the treatmentsolution. In conventional processes for the removal of hydrogen sulfide,transportation cost related to shipping large volumes of treatmentsolutions to the process site are significant. For instance triazinebased chemicals require >1 gal per lb of sulfur removed. By utilizingproduced water as described above, chemicals already available in theproduced water can be used and do not have to be shipped to the siteresulting in significant operational cost savings. Further, the presentdisclosure requires only a small addition of catalyst, resulting in asignificant savings in logistics. Additionally, prior known sulfurtreating units such as amine/claus systems or iron-redox requiresignificantly more capital due to their corrosive nature. The lowtemperature and pressure of the oxidizer in presently disclosed systemprovides for significant ease of operation, reduced operating cost, andlower capital expense.

The processes of the present disclosure are suitable for the treatmentof hydrogen sulfide that is present as a contaminate in a subseapipeline, a wellbore, a wellhead, or any other pipeline that contains acrude oil/water mix. As indicated, preferably, a sulfur dye catalyst canbe used convert the hydrogen sulfide oil into a thiosulfate, thusyielding a clean oil product. It is economically desirable to recoverthe catalyst for reuse from the partially or fully spent liquidtreatment solution. One possible method for the recovery of the catalystrequires the use of an appropriate filtration unit operation, wheremembranes or filter media, such as granular activated carbon, are usedto trap and recover the catalyst from a liquid stream. Because oxidationof the spent catalyst in the oxidizer vessel results in the formation ofa catalyst slurry, the catalyst is particularly suitable for separationfrom the liquid solution of thiosulfate ions produced from the oxidationof sulfides that occurred in the oxidizer vessel. Because the presentlydisclosed process handles high volume of sulfides, the near completeoxidation of sulfide ions to thiosulfate is preferred for effectivefiltration. In particular, the complete oxidation of the catalyst ispreferred, i.e. ORP greater than −0.4 mV for sufficient separation ofthe oxidized (i.e. regenerated catalyst) from potassium thiosulfatesolution via filtration. As mentioned, it is also advisable to performback flushing of the filter media with a solution containing a smallamount of sulfide or other reducing medium which solubilizes thecatalyst and removes it from the filter media such that it can then beintroduced back into the process. This filtration/recovery method canalso be used to recover sulfur dye catalysts from other industrial wastestreams and to then utilize the recovered catalyst as a reagent in theprocess of treating hydrogen sulfide contaminated streams.

In one embodiment, sulfur dye catalyst could be recovered from anaqueous solution by adsorption on a solid media, for example, CalgonFiltrasorb 200 carbon. When the carbon absorption media containing thesulfur dye catalyst is subsequently contacted with a solution containing2000 ppm (as sulfur) sodium sulfide, the catalyst will reduce to itssoluble form and will be released from the carbon adsorption media. Thesoluble catalyst can then be used with the regenerated catalyst tooxidize sulfides in a feed stream to produce thiosulfate. Subsequentaddition of an oxygen containing gas stream will oxidize the catalystback to its insoluble form (i.e., a slurry or semi-solid).

Other filter media can be used, for example, membranes like Tri-sep FlatXN45 polypiperiazine amide (PPA) nano-filtration membrane having amembrane cut-off of 500 Da and being compatible in 2-11 pH.

In yet another embodiment of the present disclosure, a portion of theregenerated treatment solution can be removed from the oxidizer to notonly prevent a build-up of thiosulfate within the process, but also torecover the thiosulfates as useful and economically valuable byproduct.Such a removed liquid stream would preferably be filtered as describedabove to recover the catalyst present in the regenerated treatmentsolution. Once the catalyst is removed, an aqueous solution containingthiosulfate anions and salts is obtained. This thiosulfate solution canthen be fed to an ion exchange resin system. The resin can be eitheranion or cation exchange, for example, acrylic or methacrylic withvarious crosslink monomer, sulfonated copolymer resins of styrene anddivinyl benzene, quaternized amine resins, and dimethylethanol aminecopolymer resin, to name a few. The thiosulfate ions can be exchanged toimprove the strength (concentration) of the solution or swap cations.For instance, a cation exchange resin can be pre-loaded with sodiumcations through treatment of the resin with a solution of sodiumchloride. A thiosulfate solution obtained from the catalyst filtrationstep containing ammonium thiosulfate could then be contacted with thepre-loaded sodium cation resin. The ammonia (ammonium cation) will beswapped for sodium to produce a liquid stream of sodium thiosulfate.Once all the sodium is swapped from the ion exchange resin, the ammoniasaturated resin can then be regenerated exposing the resin to a sodiumchloride solution to displace the ammonia such that the swap of thestored ammonia from the resin will yield an ammonium chloride solutionwhile regenerating the resin with sodium ions for reuse.

Potassium thiosulfate can also be made by exchanging the ammonium cationin an ammonium thiosulfate solution for potassium ions in a regenerable,potassium-loaded ion exchange resin under ion exchange conditions. Theresulting potassium thiosulfate product can be packaged as a liquidfertilizer product either with or without an intermediate concentrationstep. The ammonium-laden resin is regenerated to its potassium form bycontact with a solution of potassium chloride under suitable ionexchange conditions. The ammonium chloride solution produced by theregeneration step can be also used as a lower grade liquid fertilizer.Thus, this embodiment makes two fertilizers of different grades forvaluable production on each phase of the ion exchange process cycle.

Preferably, the ion exchange to make potassium thiosulfate is performedat a temperature within the range from about 10° C. to about 35° C., andmost preferably at an ambient temperature within a range from about 15°C. to about 30° C. The ion exchange temperature ranges for regeneratingthe resin and forming ammonium chloride are generally the same as thoseused for the ion exchange. In a particularly preferred embodiment, theresin is charged with 20 wt. % potassium chloride at ambienttemperature. Generally, the total content of K⁺ charged to the systemshould be 1.25 times higher than the total capacity of the resin.

The amount of oxygen fed to the oxidizer is controlled based on measuredORP in the absorber or oxidizer or both. Any excess oxygen containinggas from the oxidation vessel is removed. A liquid stream of regeneratedliquid treatment solution comprising the thiosulfate and the regeneratedsulfur dye catalyst is also removed from the oxidizer separately. Theregenerated liquid treatment solution can be recycled back to be mixedwith the liquid treatment solution being fed to the absorber. The amountof liquid treatment solution fed to the absorber can be controlled basedon measured ORP in the absorber, oxidizer or both. The thiosulfateconcentration is maintained at a predetermined amount in the regeneratedliquid treatment solution by removing a portion of the regeneratedliquid treatment solution from the process.

In yet another possible processing scheme, produced water is removed andrecovered from an oil and gas well and then subjected to a separationprocess, preferably a 3-phase separation process, where an aqueous phaseis obtained from the produced water. The aqueous phase is then fed tothe oxidizer vessel.

Still another variant of the present disclosure includes dividing theliquid stream of regenerated liquid treatment solution comprising thethiosulfate and the regenerated sulfur dye catalyst into a first and asecond portion, where the second portion of regenerated liquid treatmentsolution is recycled to the absorber. The first portion is fed into aseparate separation process where the regenerated sulfur dye catalyst isseparated from the thiosulfate by a filtration step and is recirculatedto the absorber vessel. The filtration step uses a filter media thatcollects the regenerated sulfur dye catalyst and produces a thiosulfatesolution that can be introduced into an ion exchange column where athiosulfate product stream is produced.

It is also may be desirable to include in the separation process aback-flushing step that removes the regenerated sulfur dye catalyst fromthe filter media so that it can be recovered and reused. One possibleback flushing step comprises contacting the filter media with a liquidsolution containing sulfide ions.

These and other objects will become more apparent from the detaileddescription of the preferred embodiment contained below.

BRIEF DESCRIPTION OF THE FIGURES

In the following detailed description of the present disclosure,reference will be made to the accompanying drawings, of which,

FIG. 1 schematically illustrates one possible embodiment of the presentdisclosure;

FIG. 2 schematically represents a variation of the process flow schemedepicted in FIG. 1;

FIG. 3 schematically represents another variation of the process flowscheme depicted in FIG. 1;

FIG. 4 schematically represents yet another variation of the processflow scheme depicted in FIG. 1; and

FIG. 5 schematically represents yet another variation of the processflow scheme depicted in FIG. 1.

DETAILED DESCRIPTION

FIGS. 1-5 present different process flow schemes for the treatment of ahydrocarbon process stream containing oil, gas, and/or water. Suchprocess streams can be found in subsea pipelines, wellbores, andwellheads that are contaminated with hydrogen sulfide (H₂S). Many of theunit operations, such as separators 8, absorbers 207, oxidizers 11, 209,358 and filtration processes 37, 206, 362, 370, are similar in designand operation in each of the different process flow schemes.

FIG. 1 illustrates a continuous process for injecting a liquid treatmentsolution 2 into a subsea pipeline 104 that can contain an oil/water mix,typically a crude oil/water emulsion, contaminated with hydrogen sulfide(H₂S). The injection point 102 is chosen a distance 103 below sea level101 to define a scavenger region 104 a within the subsea pipeline.Within the scavenger region the H₂S is absorbed into the liquidtreatment solution where the sulfide from the H₂S reacts with a sulfurdye catalyst contained in the liquid treatment solution forming anadmixture. This admixture flows via an offshore platform 100 in line 1into a separator 8 where undissolved gases are vented via line 9. Atreated oil stream 6 substantially H₂S free is removed from theseparator for further processing or refining.

The liquid treatment solution injected via line 2 into the subseapipeline 104 can be composed of a mixture of fresh liquid treatmentsolution 3 with regenerated liquid treatment solutions 39 and 14, asmore fully described below. The liquid treatment solution, for example,could contain a sulfur dye catalyst and potassium carbonate and/orpotassium bicarbonate and, in the case where regenerated treatmentsolution is mixed with the fresh treatment solution, an amount ofpotassium thiosulfate. Further, the liquid treatment solution couldcontain cations selected from the group consisting of ammonia, lithium,calcium, magnesium, potassium, and sodium. Likewise, the liquidtreatment solution can contain anions, including hydroxide andcarbonate. These cations and anions can be found in produced water,evaporator blowdown, process water, cooling water blowdown, or anyaqueous stream containing the anions/cations in any concentrationbetween 0 wt. % and the solubility limit of the ions.

A spent treatment stream 10 containing spent catalyst and potassiumthiosulfate is removed from the separator 8, where the pressure istypically less than 5 barg and is introduced into the oxidizer 11. Theseparator 8 and oxidization vessel (oxidizer) 11 can be operated inseries flow. An oxygen-containing gas 13, such as air, is introducedinto the oxidizer 11, preferably through a sparger 21. The amount ofoxygen added to the oxidizer is controlled by monitoring oxidationreduction potential (ORP) values. For example, one method would includeusing a sensor located in the absorber and/or in the oxidizer to measurethe ORP values of the solution(s). The measured ORP could be monitoredby control valve which then adjusts the amount of oxygen containing gassupplied to the oxidizer 11 through line 13. Alternatively, the ORPvalue of the regenerated liquid treatment solution exiting the oxidizerin line 14 could be measured, monitored and used to control the flow oramount of oxygen containing gas that is introduced into the oxidizer.Likewise, or in addition to, another method could include using themeasured ORP values obtained from sensors in the scavenger region 104 aof the subsea pipeline 104 and/or in the oxidizer to operate a controlvalve which then adjusts the amount of liquid treatment solution that isinjected into the pipeline 104 through injection point 102 using line 2.

Alternatively, or in addition to, the concentration of H₂S in thetreated oil stream 6 can be monitored and measured to control the amountof oxygen that is added to the oxidizer. Excess oxygen-containing gas isremoved from the top of the oxidizer 11 through line 12. As mentioned,the spent catalyst fed from separator 8 is regenerated by an oxidationreaction in oxidizer 11. Oxidation of the catalyst causes the catalystto convert from a soluble form to an insoluble form (i.e., forming aslurry), which as described below can be recycled back to the injectionpoint at the start of the scavenger region. The catalyst-sulfide complexformed in the scavenger region 104 a is also oxidized to producethiosulfate and returns the regenerated catalyst to the aqueoussolution. A regenerated liquid stream of treatment solution containingthe regenerated catalyst and thiosulfates is removed from the oxidizervia stream 14 and recycled for use as part of the liquid treatmentsolution injected into the subsea pipeline, this recycle stream can bemixed with fresh or make-up treatment solution 3 containing activesulfur dye catalyst and potash. In order to prevent a build-up ofthiosulfate in the process, a portion of regenerated liquid treatmentsolution is removed form oxidizer 11 via stream 15 for furtherprocessing, as will be described in more detail below, to recover thethiosulfate as a useful byproduct. Preferably, the regenerated catalystshould be removed by filtration first and recycled back for mixing intoline 2. Additional dewatering may also be required of the recoveredthiosulfate solution or the thiosulfate solution byproduct can betreated to recover the thiosulfate ion, for example, through an ionexchange process.

In another possible variant of the present disclosure, the stream 15 isfurther treated using a combination of a filtration unit operation 37and optionally an ion exchange operation. A filter media is used tocollect and separate the regenerated catalyst that is suspended in theliquid treatment solution as a slurry or semi-solid when it is removedfrom the oxidizer. The filtration process is run until the filter mediabecomes occluded or full. Although the details are not shown, thefiltration process 37 would include process piping where a flushingliquid 50, preferably containing sulfides, could be used to backflushand clean the collected catalyst from the filter media. This backflushof recovered catalyst would be removed as stream 39 and could be fedback to the scavenger region of the pipeline by mixing with theregenerated liquid treatment solution in line 14 to form the mixture inline 2. Preferably two or more filtration units could be operated inparallel (in a swing configuration) to maintain a continuous filteringoperation. In other words, once a filter is occluded, the flow could bediverted from the occluded filter media to a clean filter so that backflushing of the occluded filter could be performed. The cycle would berepeated each time the filter media becomes full of the catalyst.

In yet a further variant of the processes disclosed above, the liquidsolution recovered from filtration process 37 can be removed via line 38for storage/transport 40 and eventual removable from the process forfurther treatment/application. One possible further processing stepincludes an ion exchange process. The ion exchange process preferablyuses a plurality of one or more discrete ion exchange resin column bedsdisposed in serial, cascading flow relation. To maintain a continuousoperation, it may be necessary to have two or more of these serial bedsarranged in parallel so that a swing-type operation could be employedsimilar to that described for the filtration process 37. Appropriatevalves and control systems that are within the existing skill of the artcan be used to control the switchover from a column sequence operatingin exchange mode to operation in regeneration mode. When properlyperformed, the ion exchange batch operation can be operated as asubstantially continuous process. Higher levels of thiosulfate purityare attainable with increasing numbers of consecutive exchange beds.Resin regeneration solution can be introduced into the beds as needed.An ion exchanged liquid product comprising thiosulfate is removed fromthe ion exchange process.

FIG. 2 presents another possible process of the instant disclosure wherethe liquid treatment solution in line 2 is injected into a wellbore 203.A wellbore is a hole that is drilled to aid in the exploration andrecovery of natural resources including oil, gas or water. A wellbore isthe actual hole that forms the well. A wellbore can be encased bymaterials such as steel and cement, or it may be uncased. The injectionpoint 202 where line 2 supplies the liquid treatment solution definesthe start of a scavenger region 201, which ends at ground level 206 ofthe well 200. Similar to the subsea pipeline discussed above, wellbore203 contains a mix of oil and water contaminated with H₂S. For instance,gas (C1-C4), hydrocarbon oil (C5-C19), brine (0-30 wt %) and 0-1000 ppmH2S. A typical gas to oil ratio 0-100 v/v and gas to water ratio 0-100v/v. The process shown in FIG. 2 to treat fluids in a wellbore is verysimilar to that shown in FIG. 1, except two separators 8 a, 8 b are usedin series. The two separators in series provides the stage separation tomaximize oil recovery, to minimize catalyst entrainment and handleoperation issues such as foaming. It should be noted in some cases(especially, in case of limited space at off-shore facility) one-stagegas-oil-water (3 phase) separator could be operated as shown in earlierFIG. 1. Separator 8 a removes undissolved gases 9 from a mixture 204 ofspent treatment solution and treated oil, which is then fed to thesecond separator 8 b, where the treated oil 205 is separated from thespent liquid treatment solution 10 containing the spent sulfur dyecatalyst bound with the sulfide from the H₂S originally contained in thewellbore fluids. The separated treated oil 205 can be further processed210.

FIG. 3 is a possible variant of the process illustrated in FIG. 2 wherethe separated dissolved gases in line 9 may contain residual H₂S. Insuch cases, the gases in line 9 are fed to an absorber 207, where theH₂S contacts a liquid treatment solution 215 added to a top portion ofthe absorber 207 such that it contacts the up flowing gases in acountercurrent contacting scheme. Optionally, a packed bed 207 a ofsolid media can be used to increases contact surface area of the gaseswith the downflowing liquid treatment solution. This can also beaccomplished using a type of bubble column. The absorber can operate ata pressure of 30 barg. The ratio of the liquid treatment solution to thegas feed is dependent on the quantity of H₂S in the gas feed 9, butcontains a molar ratio of catalyst greater than 1 as compared to themoles of H₂S in the feed.

The H₂S present in the gas stream 9 is absorbed into the treatmentsolution 215 as sulfide ions that then bind to the sulfur dye catalystcontained in the liquid treatment solution to form a spent sulfur dyecatalyst. The sulfur dye catalyst in its oxidized form reacts with thesulfide ions to form the reduced state of the catalyst. i.e., a spentcatalyst. A substantially H₂S-fee gas stream 211 is removed from the topof absorber 207 and sent for storage, transportation, released to theatmosphere, or further processing.

A spent treatment stream 212 containing spent sulfur dye catalyst andthiosulfate is removed from the absorber 207 and introduced into flashdrum where the pressure is reduced to less than 5 barg to remove solublegases, such as CO₂ and H₂O, via stream 208 a. Any unconverted H₂S, ifpresent, would also be removed in stream 208 a. The spent liquidtreatment solution in line 213 exiting flash drum 208 is then fed to asecond oxidizer 209 where an oxygen-containing gas 221, such as air, isintroduced into the oxidizer 209, preferably through a sparger. Asindicated above, the amount of oxygen added to the oxidizer iscontrolled by monitoring oxidation reduction potential (ORP) values.Excess oxygen-containing gas is removed via line 216. Regenerated liquidtreatment solution is removed via 214 where a portion of it can berecycled via line 223 back to the absorber 207. Fresh liquid treatmentsolution or make-up treatment solution can be added via line 217 to line223 and the mixture sent to the absorber via line 215. Another portionof the regenerated liquid treatment solution can be sent to a filtrationprocess 206 via line 222 where filtered regenerated catalyst isrecovered using a back-flush solution 218. The recovered regeneratedsulfur dye catalyst can then be sent via line 219 to mix with themake-up treatment solution in line 217. Filtered liquid regeneratedliquid treatment solution 226 containing thiosulfate is removed from thefiltration process 206 and sent, for example, via transport 40, forfurther processing.

FIG. 4 presents an almost identical processing flow scheme as shown inFIG. 3, except here, the liquid treatment solution in line 2 is injecteddirectly into a wellhead 1 located downstream from well 300 and aboveground from wellbore 302, where the injection point 301 a is located apredetermined distance from separator 8 a to define a scavenger region301. All other processing steps are essentially the same as thatdescribed above. As described above, the predetermined distance can bedetermined by modeling in computational flow dynamics (CFD) to determinethe appropriate length or distance of pipe that is required to achieveoptimum and/or maximum removal of the hydrogen sulfide that is presentin the fluid flowing through the pipe prior to the injection of theliquid treatment, i.e., prior to the beginning of the scavenger zone.

FIG. 5 presents another flow scheme alternative for injecting liquidtreatment solution into a wellhead 1 at an injection point 301 a. Theflow scheme is essentially the same as described above for the processdepicted in FIG. 4, except here the treated oil that is removed via line205 removed from separator 8 b contains residual H₂S. Stream 205 isfurther treated by injecting the liquid treatment solution via line 349upstream of an inline-mixer 351. The injected solution can be acombination of fresh make-up liquid treatment solution in line 354 andrecycled regenerated sulfur dye catalyst via line 355. The injectioninto line 205 can be performed using quill 350. After mixing in thein-line mixer 351, an exit stream 353 is fed to phase separator 356where treated oil substantially free of H₂S is removed via line 304 forfurther processing 210. A spent liquid treatment solution is removed vialine 357 from phase separator 356 and introduced into a third oxidizer358. An oxygen-containing gas 359 is introduced into oxidizer 358 andexcess oxygen-containing gas is removed via line 360. A stream ofregenerated liquid treatment solution is removed via line 303 andrecycled back for mixing with fresh make-up liquid treatment solution inline 349 prior to injection upstream of the in-line mixer 351.Additionally, regenerated sulfur dye catalyst in line 355 recovered infiltration process 362 can be mixed with the regenerated liquidtreatment solution in line 303. Filtration process 362 can employ aback-flushing solution via line 361 to assist in recovering theregenerated sulfur dye catalyst. Liquid treatment solution containingthiosulfate can be removed from the filtration process 362 via line 363and transported 40 for further processing.

The foregoing description of the specific embodiments will so fullyreveal the general nature of the invention that others can, by applyingcurrent knowledge, readily modify and/or adapt for various applicationsuch specific embodiments without departing from the generic concept,and therefore such adaptations and modifications are intended to becomprehended within the meaning and range of equivalents of thedisclosed embodiments. It is to be understood that the phraseology orterminology herein is for the purpose of description and not oflimitation.

The means, materials, and steps for carrying out various disclosedfunctions may take a variety of alternative forms without departing fromthe invention. Thus, the expressions “means to . . . ” and “means for .. . ”, or any method step language as may be found in the specificationabove or the claims below, followed by a functional statement, areintended to define and cover whatever structural, physical, chemical orelectrical element or structure, or whatever method step, which may nowor in the future exist which carries out the recited function, whetheror not precisely equivalent to the embodiment or embodiments disclosedin the specification above, i.e., other means or steps for carrying outthe same function can be used; and it is intended that such expressionsbe given their broadest interpretation.

The invention claimed is:
 1. A process to remove hydrogen sulfide from ahydrocarbon stream contained in a wellhead pipeline comprising:injecting a liquid treatment solution comprising a sulfur dye catalystdirectly into a pipeline that is in fluid communication with a wellbore, where the pipeline contains a hydrocarbon and hydrogen sulfide andthe injection of the liquid treatment solution forms an admixture suchthat the hydrogen sulfide is absorbed into the liquid treatment solutionand reacts to form a spent sulfur dye catalyst that is contained withinthe admixture; directing the admixture into a separator where treatedhydrocarbon and dissolved gas is separated from a spent treatmentsolution comprising the spent sulfur dye catalyst and water; introducingthe spent treatment solution into an oxidation vessel containing anoxygen containing gas; oxidizing sulfide that is bound to the sulfur dyecatalyst in the oxidation vessel to form a regenerated sulfur dyecatalyst and thiosulfate; removing the thiosulfate and the regeneratedsulfur dye catalyst as a liquid stream of regenerated liquid treatmentsolution from the oxidation vessel; and maintaining a predeterminedthiosulfate concentration in the regenerated liquid treatment solutionby removing a portion of the regenerated liquid treatment solution fromthe process.
 2. The process of claim 1 further comprising the step ofrecycling the regenerated liquid treatment solution by mixing with theliquid treatment solution before the injection into the pipeline.
 3. Aprocess to remove hydrogen sulfide from a hydrocarbon stream containedin a wellhead pipeline comprising: adding a liquid treatment solutioncomprising a sulfur dye catalyst directly into a pipeline that is influid communication with a well bore to form an admixture; directing theadmixture to a first separator to remove dissolved gasses from theadmixture and removing the degassed admixture from the first separatorand into a second separator where treated oil is separated and removedfrom spent liquid treatment solution; oxidizing the spent treatmentsolution in a first oxidizer to form thiosulfate and regenerated liquidtreatment solution; directing the dissolved gases to an absorbercontaining liquid treatment solution from a second oxidizer and formingtreated oil that is separated and removed from spent liquid treatmentsolution; removing from the second oxidizer thiosulfate and regeneratedliquid treatment solution; maintaining a predetermined thiosulfateconcentration in the regenerated liquid treatment solution that isremoved from the second oxidizer by removing a portion of theregenerated liquid treatment solution from the process.
 4. A process totreat hydrogen sulfide present in a wellhead comprising: a) injecting aliquid treatment solution comprising a sulfur dye catalyst into awellhead pipeline containing a hydrocarbon and hydrogen sulfide to forman admixture, where the point of injection of the liquid treatmentsolution into the wellhead pipeline is at a predetermined distance aboveground level to define a scavenger region; b) absorbing the hydrogensulfide into the liquid treatment solution within the scavenger regionto form a spent sulfur dye catalyst comprising sulfide bound with thesulfur dye catalyst; c) directing the admixture into a first separatorwhere the hydrocarbon is separated from a spent treatment solutioncomprising the spent sulfur dye catalyst and water; d) introducing thespent treatment solution into an oxidation vessel containing an oxygencontaining gas where the sulfide bound to the sulfur dye catalystoxidizes to thiosulfate and a regenerated sulfur dye catalyst is formed;and e) maintaining a predetermined thiosulfate concentration in aregenerated liquid treatment solution by removing from the oxidationvessel and from the process a liquid stream of the regenerated liquidtreatment solution comprising the thiosulfate and the regenerated sulfurdye catalyst; and f) removing dissolved gas from the first separator anddirecting the dissolved gas into an absorber where the dissolved gascomprising hydrogen sulfide contacts the liquid treatment solution. 5.The process of claim 4 further comprising directing the dissolved gasinto a bottom portion of the absorber such that the dissolved gas flowsupward contacting the liquid treatment solution flowing downward from atop portion of the absorber.
 6. The process of claim 4 furthercomprising introducing the liquid stream of regenerated liquid treatmentsolution removed from the oxidation vessel into a second separationprocess where the regenerated sulfur dye catalyst is separated from thethiosulfate.
 7. The process of claim 6 further comprising removing theregenerated sulfur dye catalyst from the second separation process andmixing it with the liquid treatment solution prior to injection into thewellhead.
 8. The process of claim 4 further comprising controllingresidence time of the contact within the absorber such that the hydrogensulfide is absorbed into the liquid treatment solution and reacts toform a spent sulfur dye catalyst comprising sulfide bound with thesulfur dye catalyst.
 9. The process of claim 8 further comprisingremoving a gas stream from the absorber and separately removing thespent sulfur dye catalyst from the absorber and introducing the spentsulfur dye catalyst into a second oxidation vessel to contact an oxygencontaining gas to oxidize sulfide bound to the sulfur dye catalyst toform thiosulfate and a regenerated sulfur dye catalyst.
 10. The processof claim 9 further comprising removing from the second oxidation vessela liquid stream of regenerated liquid treatment solution comprising thethiosulfate and the regenerated sulfur dye catalyst and dividing theregenerated liquid treatment solution into a first and a second portion;and recycling the second portion of regenerated liquid treatmentsolution to the absorber.
 11. The process of claim 10 further comprisingintroducing the first portion into a filtration step where theregenerated sulfur dye catalyst is separated from the thiosulfate and isrecirculated to the absorber vessel; and removing the thiosulfate fromthe process, where the filtration step uses a filter media that collectsthe regenerated sulfur dye catalyst.
 12. The process of claim 11 wherethe filtration process includes a back-flushing step that removes theregenerated sulfur dye catalyst from the filter media.
 13. The processof claim 12 where the back-flushing step comprises contacting the filtermedia with a liquid solution.